Subpart D—Oil and Gas Drilling Operations · PDF file§250.50 Control of wells. ......

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not significantly affecting the air qual-ity of an onshore area of the State.

(g) Emission monitoring requirements.The lessee shall monitor, in a mannerapproved or prescribed by the RegionalSupervisor, emissions from the facilityfollowing the installation of emissioncontrols. The lessee shall submit thisinformation monthly in a manner andform approved or prescribed by the Re-gional Supervisor.

(h) Collection of meteorological data.The Regional Supervisor may requirethe lessee to collect, for a period oftime and in a manner approved or pre-scribed by the Regional Supervisor,and submit meteorological data from afacility.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988]

Subpart D—Oil and Gas DrillingOperations

§ 250.50 Control of wells.The lessee shall take necessary pre-

cautions to keep its wells under con-trol at all times. The lessee shall uti-lize the best available and safest drill-ing technology in order to enhance theevaluation of conditions of abnormalpressure and to minimize the potentialfor the well to flow or kick. The lesseeshall utilize personnel who are trainedand competent and shall utilize andmaintain equipment and materials nec-essary to assure the safety and protec-tion of personnel, equipment, naturalresources, and the environment.

§ 250.51 General requirements.(a) Fitness of drilling unit. (1) Drilling

units shall be capable of withstandingthe oceanographic, meteorological, andice conditions for the proposed seasonand location of operations.

(2) Prior to commencing operation,drilling units shall be available forcomplete inspection by the District Su-pervisor.

(3) The lessee shall provide informa-tion and data on the fitness of thedrilling unit to perform the proposeddrilling operation. The informationshall be submitted with or prior to thesubmission of Form MMS–123, Applica-tion for Permit to Drill (APD), in ac-cordance with § 250.64. The District Su-

pervisor may require the submission ofa third-party review of the design ofdrilling units which are of a unique de-sign and/or not proven for use in theproposed environment if the DistrictSupervisor believes that the informa-tion submitted by the lessee is insuffi-cient to demonstrate suitability of theunit for use at the proposed drill site.A design Certified Verification Agentapproved in accordance with § 250.133 ofthis part shall be used for any requiredthird-party review.

(b) Drilling unit safety devices. (1) Nolater than May 31, 1989, all drillingunits shall be equipped with a safetydevice which is designed to prevent thetraveling block from striking thecrown block. The device shall bechecked for proper operation weeklyand after each drill-line slipping oper-ation. The results of the operationalcheck shall be entered in the driller’sreport.

(2) No later than May 31, 1989, diesel-engine air intakes shall be equippedwith a device to shut down the dieselengine in the event of runaway. Dieselengines which are continuously at-tended shall be equipped with either re-mote operated manual or automaticshutdown devices. Diesel engines whichare not continuously attended shall beequipped with automatic shutdown de-vices.

(c) Oceanographic, meteorological, anddrilling unit performance data. Wheresuch information is not otherwise read-ily available, upon request of the Dis-trict Supervisor, lessees shall collectand report oceanographic, meteorologi-cal, and drilling unit performance data,and monitor ice conditions, if applica-ble, during the period of operations.The type of information to be collectedand reported will be determined by theDistrict Supervisor in the interests ofsafe conduct of operations and thestructural integrity of the drillingunit.

(d) Foundation requirements. When thelessee fails to provide sufficient infor-mation pursuant to §§ 250.33 and 250.34of this part to support a determinationthat the seafloor is capable of support-ing a specific bottom-founded drillingunit under the site-specific soil andoceanographic conditions, the DistrictSupervisor may require that additional

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surveys and soil borings be performedand the results be submitted for reviewand evaluation by the District Super-visor before approval is granted forcommencing drilling operations.

(e) Tests, surveys, and samples. (1) Thelessee shall conduct tests, obtain welland mud logs or surveys, and take sam-ples to determine the reservoir energy;the presence, quantity, and quality ofoil, gas, sulphur, and water; and theamount of pressure in the formationspenetrated. The lessee shall take for-mation samples or cores to determinethe identity, fluid content, and charac-teristics of any penetrated formationin accordance with requirements ap-proved or prescribed by the DistrictSupervisor.

(2) Inclinational surveys shall be ob-tained on all vertical wells at intervalsnot exceeding 1,000 feet during the nor-mal course of drilling. Directional sur-veys giving both inclination and azi-muth shall be obtained on all direc-tional wells at intervals not exceeding500 feet during the normal course ofdrilling and at intervals not exceeding100 feet in all portions of the hole whenangle-changes are planned.

(3) On both vertical and directionallydrilled wells, directional surveys givingboth inclination and azimuth shall beobtained at intervals not exceeding 500feet prior to or upon setting surface orintermediate casing, liners, and attotal depth. Composite directional sur-veys shall be prepared with the inter-val shown from the bottom of the con-ductor casing or, in the absence of con-ductor casing, from the bottom of thedrive or structural casing to totaldepth. In calculating all surveys, a cor-rection from the true north to Univer-sal-Transverse-Mercator-Grid-north orLambert-Grid-north shall be madeafter making the magnetic-to-true-north correction. A compositedipmeter directional survey or a com-posite measurement-while-drilling(MWD) directional survey including alisting of the directionally computedinclinations and azimuths on a wellclassified as vertical will be acceptableas fulfilling the applicable require-ments of this paragraph. In the event acomposite MWD survey is run, amultishot survey shall be obtained at

each casing point in order to confirmthe MWD results.

(4) Wells are classified as vertical ifthe calculated average of inclinationreadings weighted by the respective in-terval lengths between readings fromsurface to drilled depth does not exceed3 degrees from the vertical. When thecalculated average inclination readingsweighted by the length of the respec-tive interval between readings from thesurface to drilled depth exceeds 3 de-grees, the well is classified as direc-tional.

(5) The Regional Supervisor at the re-quest of a holder of an adjoining leasemay, for the protection of correlativerights, furnish a copy of the directionalsurvey for a well drilled within 500 feetof the adjacent lease to that lease-holder.

(f) Fixed drilling platforms. Applica-tions for installation of fixed drillingplatforms or structures, including arti-ficial islands, shall be submitted in ac-cordance with the provisions of subpartI, Platforms and Structures, of thispart. Mobile drilling units which havetheir jacking equipment removed orhave been otherwise immobilized areclassified as fixed drilling platforms.

(g) Equipment movement. The move-ment of drilling rigs and related equip-ment on and off an offshore platform orfrom well to well on the same offshoreplatform, including rigging up and rig-ging down, shall be conducted in a safemanner. All wells in the same well-baywhich are capable of producing hydro-carbons shall be shut in below the sur-face with a pump-through-type tubingplug and at the surface with a closedmaster valve prior to moving such rigsand related equipment, unless other-wise approved by the District Super-visor. A closed surface-controlled sub-surface safety valve of the pump-through-type may be used in lieu of thepump-through-type tubing plug, pro-vided that the surface control has beenlocked out.

(h) Emergency shutdown system. Whendrilling operations are conducted on aplatform where there are other hydro-carbon-producing wells or other hydro-carbon flow, an Emergency Shutdown


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System (ESD) manually controlled sta-tion shall be installed near the driller’sconsole.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13,1988, as amended at 54 FR 50616, Dec. 8, 1989;55 FR 47752, Nov. 15, 1990; 58 FR 49928, Sept.24, 1993]

§ 250.52 Welding and burning practicesand procedures.

(a) General requirements. (1) For thepurpose of this rule, the terms weldingand burning are defined to include arcor fuel-gas (acetylene or other gas) cut-ting and arc or fuel-gas welding.

(2) All offshore welding and burningshall be minimized by onshore fabrica-tion when feasible. The requirementsset forth in paragraphs (b), (c), and (d)of this section shall be applicable toany welding or burning practice or pro-cedure performed on the following:

(i) An offshore mobile drilling unitduring the drilling mode;

(ii) A mobile workover unit duringany drilling, completion, recompletion,remedial, repair, stimulation, or otherworkover activity;

(iii) A platform, structure, artificialisland, or other installation during anydrilling, well-completion, well-workover, or production operation; and

(iv) A platform, structure, artificialisland, or other installation which con-tains a well open to a hydrocarbon-bearing zone.

(3) All water-discharge-point sourcesfrom hydrocarbon-handling vesselsshall be monitored in order to stopwelding and burning operations in caseflammable fluids are discharged as aresult of equipment upset or malfunc-tion.

(4) Equipment containing hydro-carbons or other flammable substancesshall be relocated at least 35 feet hori-zontally from the work site. Similarequipment located at a lower elevationwhere slag, sparks, or other burningmaterials could fall shall be relocatedat least 35 feet from the point of im-pact. If relocation is impractical, ei-ther the equipment shall be protectedwith flame-proofed covers or otherwiseshielded with metal or fire-resistantguards or curtains, or the contentsshall have been rendered inert.

(b) Welding, burning, and hot tappingplan. Each lessee shall submit for ap-

proval by the District Supervisor a‘‘Welding, Burning, and Hot TappingSafe Practices and Procedures Plan’’prior to beginning the first drillingand/or production operations on alease. The plan shall include the quali-fication standards or requirements forpersonnel who the lessee will authorizeto conduct welding, burning, and hottapping operations and the methods bywhich the lessee will assure that onlytrained personnel who meet suchstandards or requirements are utilized.A copy of this plan and approval lettershall be available on the facility wherethe welding is conducted. Any persondesignated as a welding supervisorshall be thoroughly familiar with thisplan. An approved plan is requiredprior to conducting any welding, burn-ing, or hot tapping operation. All weld-ing and burning equipment shall be in-spected by the welding supervisor orthe lessee’s designated person in chargeprior to beginning any welding, burn-ing, or hot tapping. All engine-drivenwelding machines shall be equippedwith spark arrestors and drip pans.Welding leads shall be completely insu-lated and in good condition, oxygenand fuel gas bottles shall be secured ina safe place, and leak-free hoses shallbe equipped with proper fittings,gauges, and regulators.

(c) Designated safe-welding and burn-ing areas. The lessee may establish anddesignate areas determined to be safe-welding areas. These designated areasshall be identified in the plan, and adrawing showing the location of theseareas shall be maintained on the facil-ity.

(d) Undesignated welding and burningareas. All welding and burning, whichcannot be done in an approved safe-welding area, shall be performed incompliance with the following:

(1) Prior to the commencement ofany of these operations, the lessee’sdesignated person in charge at the in-stallation shall inspect the qualifica-tions of the welder(s) to assure that thewelder(s) is properly qualified in ac-cordance with the approved qualifica-tion standards or requirements forwelders. The designated person incharge and the welder(s) shall inspectthe work area and area(s) at elevationsbelow the work area where slag,


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sparks, or other hot materials couldfall for potential fire and explosionhazards. After it has been determinedthat it is safe to proceed with the weld-ing and burning operation, the des-ignated person-in-charge shall issue awritten authorization for the work.

(2) During these welding or burningoperations, one or more persons shallbe designated as a fire watch. The per-son(s) assigned as a fire watch shallhave no other duties while actual weld-ing or burning operations are inprogress. If the operation is to be in anarea which is not equipped with a gasdetector, the fire watch shall alsomaintain a continuous surveillancewith a portable gas detector during thewelding and burning operation. Thefire watch shall remain on duty for aperiod of 30 minutes after welding orburning operations have been com-pleted.

(3) Prior to any of these operations,the fire watch shall have in their pos-session firefighting equipment in a usa-ble condition.

(4) No welding or burning operation,other than approved hot tapping, shallbe done on piping, containers, tanks, orother vessels which have contained aflammable substance unless the con-tents have been rendered inert and aredetermined to be safe for welding orburning by the designated person incharge.

(5) If drilling, well-completion, well-workover, or wireline operations are inprogress, welding operations in otherthan approved safe-welding areas shallnot be conducted unless the well(s) inthe area where drilling, well-comple-tion, well-workover, or wireline oper-ations are in progress contain non-combustible fluids and the entry of for-mation hydrocarbons into the wellboreis precluded.

(6) If welding or burning operationsare conducted in or within 10 feet of awell-bay or production area, all produc-ing wells in the well-bay or productionarea shall be shut in at the surfacesafety valve.

§ 250.53 Electrical equipment.The following requirements shall be

applicable to all electrical equipmenton all platforms, artificial islands,fixed structures, and their facilities:

(a) All engines with electrical igni-tion systems shall be equipped with alow-tension ignition system designedand maintained to minimize the re-lease of sufficient electrical energy tocause ignition of an external, combus-tible mixture or substance.

(b) All areas shall be classified in ac-cordance with API RP 500, Rec-ommended Practice for Classificationof Locations for Electrical Installa-tions at Petroleum Facilities.

(c) All electrical installations shallbe made in accordance with API RP14F, Design and Installation of Elec-trical Systems for Offshore ProductionPlatforms, except sections 7.4, Emer-gency Lighting and 9.4, Aids to Naviga-tion Equipment.

(d) Maintenance of electrical systemsshall be by personnel who are trainedand experienced with the area classi-fications, distribution system, perform-ance characteristics and operation ofthe equipment, and with the hazardsinvolved.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50616, Dec. 8, 1989; 61 FR 60024, Nov. 26,1996]

§ 250.54 Well casing and cementing.(a) General requirements. (1) For the

purpose of this subpart, the casingstrings in order of normal installationare as follows:

(i) Drive or structural,(ii) Conductor,(iii) Surface,(iv) Intermediate, and(v) Production casing.(2) The lessee shall case and cement

all wells with a sufficient number ofstrings of casing and quantity andquality of cement in a manner nec-essary to prevent release of fluids fromany stratum through the wellbore (di-rectly or indirectly) into offshore wa-ters, prevent communication betweenseparate hydrocarbon-bearing strata,protect freshwater aquifers from con-tamination, support unconsolidatedsediments, and otherwise provide ameans of control of the formation pres-sures and fluids. Cement composition,placement techniques, and waitingtime shall be designed and conductedso that the cement in place behind thebottom 500 feet of casing or totallength of annular cement fill, if less,


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attains a minimum compressivestrength of 500 pounds per square inch(psi). Cement placed across permafrostzones shall be designed to set beforefreezing and have a low heat of hydra-tion.

(3) The lessee shall install casing de-signed to withstand the anticipatedstresses imposed by tensile, compres-sive, and buckling loads; burst and col-lapse pressures; thermal effects; andcombinations thereof. Safety factors inthe casing program design shall be ofsufficient magnitude to provide wellcontrol during drilling and to assuresafe operations for the life of the well.Any portion of an annulus opposite apermafrost zone which is not protectedby cement shall be filled with a liquidwhich has a freezing point below theminimum permafrost temperature toprevent internal freezeback and whichis treated to minimize corrosion.

(4) In cases where cement has filledthe annular space back to the mudline, the cement may be washed out ordisplaced to a depth not exceeding thedepth of the structural casing shoe tofacilitate casing removal upon wellabandonment if the District Supervisordetermines that subsurface protectionagainst damage to freshwater aquifersand permafrost zones and against dam-age caused by adverse loads, pressures,and fluid flows is not jeopardized.

(5) If there are indications of inad-equate cementing (such as lost returns,cement channeling, or mechanical fail-ure of equipment), the lessee shallevaluate the adequacy of the cement-ing operations by pressure testing thecasing shoe, running a cement bondlog, running a temperature survey, or acombination thereof before continuingoperations. If the evaluation indicatesinadequate cementing, the lessee shallre-cement or take other remedial ac-tions as approved by the District Su-pervisor.

(6) A pressure-integrity test shall berun below the surface casing, the inter-mediate casing(s), and liner(s) used asintermediate casing(s). The DistrictSupervisor may require a pressure-in-tegrity test to be run at the conductorcasing shoe due to local geologic condi-tions or planned casing setting depths.Pressure-integrity tests shall be madeafter drilling new hole below the casing

shoe and before drilling more than 50feet of new hole below a respective cas-ing string. These tests shall be con-ducted either by testing to formationleak-off or by testing to a predeter-mined equivalent mud weight as speci-fied in the approved APD. A safe mar-gin, as approved by the District Super-visor, shall be maintained between themud weight in use and the equivalentmud weight at the casing shoe as deter-mined in the pressure-integrity test.Drilling operations shall be suspendedwhen the safe margin is not main-tained. Pressure-integrity and pore-pressure test results and related hole-behavior observations, such as gas-cutmud and well kicks made during thecourse of drilling, shall be used in ad-justing the drilling mud program andthe approved setting depth of the nextcasing string. The results of all testsand of hole-behavior observations madeduring the course of drilling related toformation integrity and pore pressureshall be recorded in the driller’s report.

(b) Drive or structural casing. This cas-ing shall be set by driving, jetting, ordrilling to a minimum depth as may beprescribed or approved by the DistrictSupervisor, in order to support uncon-solidated deposits and to provide holestability for initial drilling operations.If this portion of the hole is drilled, aquantity of cement sufficient to fill theannular space back to the mud lineshall be used.

(c) Conductor and surface casing re-quirements. (1) Conductor and surfacecasing setting depths. Conductor andsurface casing design and settingdepths shall be based upon relevant en-gineering and geologic factors includ-ing the presence or absence of hydro-carbons, potential hazards, and waterdepths. The approved casing settingdepths may be adjusted when thechange is approved by the District Su-pervisor to permit the casing shoe tobe set in a competent formation orbelow formations which should be iso-lated from the wellbore by casing forsafer drilling operations. However, theconductor casing shall be set imme-diately prior to drilling into forma-tions known to contain oil or gas or, ifthe presence of oil or gas is unknown,upon encountering a formation con-taining oil or gas. Upon encountering


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unexpected formation pressures, thelessee shall submit a revised casingprogram to the District Supervisor forapproval. The District Supervisor maypermit a lessee to drill a well withoutsetting conductor casing provided theinformation from approved logging andmud-monitoring programs for wellspreviously drilled in the immediatevacinity combined with other availablegeologic data are sufficient to dem-onstrate the absence of shallow hydro-carbons or hazards.

(2) Conductor casing cementing require-ments. Conductor casing shall be ce-mented with a quantity of cement thatfills the calculated annular space backto the mud line except as applicable tothe bottom of an excavation (gloryhole) or to the surface of an artificialisland. Cement fill in annular spacesshall be verified by the observation ofcement returns. In the event that ob-servation of cement returns is not fea-sible, additional quantities of cementshall be used to assure fill to the mudline.

(3) Surface casing cementing require-ments. (i) Surface casing shall be ce-mented with a quantity of cement thatfills the calculated annular space to atleast 200 feet inside the conductor cas-ing. When geologic conditions such asnear-surface fractures and faultingexist, surface casing shall be cementedwith a quantity of cement that fills thecalculated annular space to the mudline, or as approved or prescribed bythe District Supervisor.

(ii) For floating drilling operations, alesser volume of cement may be used toprevent sealing the annular space be-tween the conductor casing and surfacecasing if the District Supervisor deter-mines that the uncemented space isnecessary to provide protection fromburst and collapse pressures which maybe applied inadvertently to the annulusbetween casings during blowout pre-venter (BOP) testing operations. Anyannular space open to the drilled holeshall be sealed in accordance with therequirements for abandonment in sub-part G, Abandonment of Wells, of thispart.

(d) Intermediate casing requirements.(1) Intermediate casing string(s) shallbe set for protection when geologiccharacteristics or wellbore conditions,

as anticipated or as encountered, so in-dicate.

(2) Quantities of cement that coverand isolate all hydrocarbon-bearingzones in the well and isolate abnormalpressure intervals from normal pres-sure intervals shall be used. This re-quirement for isolation may be satis-fied by squeeze cementing prior tocompletion, suspension of operations,or abandonment, whichever occursfirst. Sufficient cement shall be used toprovide annular fill-up to a minimumof 500 feet above the zones to be iso-lated or 500 feet above the casing shoein wells where zonal coverage is not re-quired.

(3) If a liner is to be used as an inter-mediate string below a surface casingstring, it shall be lapped a minimum of100 feet into the previous casing stringand cemented as required for inter-mediate casing. When a liner is to beused as production casing below a sur-face casing string, it shall be extendedto the surface and cemented to avoidsurface casing being used as productioncasing.

(e) Production casing requirements. (1)Production casing shall be cemented tocover or isolate all zones above theshoe which contain hydrocarbons; butin any case, a volume sufficient to fillthe annular space at least 500 feetabove the uppermost hydrocarbon-bearing zone shall be used.

(2) When a liner is to be used as pro-duction casing below intermediate cas-ing, it shall be lapped a minimum of 100feet into the previous casing string andcemented as required for the produc-tion casing.

§ 250.55 Pressure testing of casing.(a) Prior to drilling the plug after ce-

menting and in the cases of plugs inproduction casing strings and linersnot planned to be subsequently drilledout, all casings, except the drive orstructural casing, shall be pressuretested to 70 percent of the minimum in-ternal-yield pressure of the casing or asotherwise approved or required by theDistrict Supervisor. If the pressure de-clines more than 10 percent in 30 min-utes or if there is another indication ofa leak, the casing shall be recemented,repaired, or an additional casing stringrun and the casing pressure tested


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again. Additional remedial actionsshall be taken until a satisfactory pres-sure test is obtained. The results of allcasing pressure tests shall be recordedin the driller’s report.

(b) Each production liner lap shall betested to a minimum of 500 psi aboveformation fracture pressure at the shoeof the casing into which the liner islapped, or as otherwise approved or re-quired by the District Supervisor. Thedrilling liner-lap test pressure shall beequal to or exceed the pressure thatwill be encountered at the liner lapwhen conducting the planned pressure-integrity test below the liner shoe. Thetest results shall be recorded on thedriller’s report. If the test indicates animproper seal, remedial action shall betaken which provides a proper seal asdemonstrated by a satisfactory pres-sure test.

(c) In the event of prolonged drill-pipe rotation within a casing stringrun to the surface or extended oper-ations such as milling, fishing, jarring,washing over, and other operationswhich could damage the casing, thecasing shall be pressure tested or eval-uated by a logging technique such as acaliper log every 30 days. The evalua-tion results shall be submitted to theDistrict Supervisor with a determina-tion of effects of operations on the in-tegrity of the casing for continuedservice during drilling operations andover the producing life of the well. Ifthe integrity of the casing in the wellhas deteriorated to an unsafe level, re-medial operations shall be conductedor additional casing set in accordancewith a plan approved by the DistrictSupervisor prior to continuing drillingoperations.

(d) After cementing any string of cas-ing other than the structural casingstring, drilling shall not be resumeduntil there has been a time lapse of 8hours under pressure for the conductorcasing string and 12 hours under pres-sure for all other casing strings. Ce-ment is considered under pressure ifone or more float valves are shown tobe holding the cement in place or whenother means of holding pressure areused.

§ 250.56 Blowout preventer systemsand system components.

(a) General. The BOP systems andsystem components shall be designed,installed, used, maintained, and testedto assure well control.

(b) BOP stacks. The BOP stacks shallconsist of an annular preventer and thenumber of ram-type preventers as spec-ified under paragraphs (e)(1), (f), and(g) of this section. The pipe rams shallbe of a proper size(s) to fit the drillpipe in use.

(c) Working pressure. The working-pressure rating of any BOP componentshall exceed the anticipated surfacepressure to which it may be subjected.The District Supervisor may approve alower working pressure rating for theannular preventer if the lessee dem-onstrates that the anticipated or ac-tual well conditions will not place de-mands above its rated working pres-sure. (Refer to related requirements in§ 250.64(f)(3)(ii) of this part.)

(d) BOP equipment. All BOP systemsshall be equipped and provided with thefollowing:

(1) An accumulator system whichshall provide sufficient capacity tosupply 1.5 times the volume of fluidnecessary to close and hold closed allBOP equipment units with a minimumpressure of 200 psi above the prechargepressure without assistance from acharging system. No later than Decem-ber 1, 1988, accumulator regulators sup-plied by rig air and without a second-ary source of pneumatic supply, shallbe equipped with manual overrides oralternately, other devices provided toensure capability of hydraulic oper-ations if rig air is lost.

(2) A backup to the primary accumu-lator-charging system which shall beautomatic, supplied by a power sourceindependent from the power source tothe primary accumulator-charging sys-tem, and possess sufficient capabilityto close all BOP components and holdthem closed.

(3) At least one operable remote BOPcontrol station in addition to the oneon the drilling floor. This control sta-tion shall be in a readily accessible lo-cation away from the drilling floor.

(4) A drilling spool with side outletsif side outlets are not provided in the


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30 CFR Ch. II (7-1-97 Edition)§ 250.56

body of the BOP stack to provide forseparate kill and choke lines.

(5) For surface BOP systems, a chokeand a kill line each equipped with twofull-opening valves. At least one of thevalves on the choke line shall be re-motely controlled. At least one of thevalves on the kill line shall be re-motely controlled except that a checkvalve may be installed on the kill linein lieu of the remotely controlled valveprovided two readily accessible manualvalves are in place and the check valveis placed between the manual valvesand the pump. For subsea BOP sys-tems, a choke and a kill line eachequipped with two full-opening valves.At least one of the valves on the chokeline and at least one of the valves onthe kill line shall be remotely con-trolled.

(6) A fill-up line above the uppermostpreventer.

(7) A choke manifold suitable for theanticipated pressures to which it maybe subjected, method of well control tobe employed, surrounding environ-ment, and corrosiveness, volume, andabrasiveness of fluids. The choke mani-fold shall also meet the following re-quirements:

(i) Manifold and choke equipmentsubject to well and/or pump pressureshall have a rated working pressure atleast as great as the rated workingpressure of the ram-type BOP’s or asotherwise approved by the District Su-pervisor;

(ii) All components of the chokemanifold system shall be protectedfrom the danger, if any, of freezing byheating, draining, or filling with properfluids; and

(iii) When buffer tanks are installeddownstream of the choke assembliesfor the purpose of manifolding thebleed lines together, isolation valvesshall be installed on each line.

(8) Valves, pipes, flexible steel hoses,and other fittings upstream of, and in-cluding, the choke manifold with pres-sure ratings at least as great as therated working pressure of the ram-typeBOP’s or as otherwise approved by theDistrict Supervisor.

(9) A wellhead assembly with a ratedworking pressure that exceeds the an-ticipated surface pressure to which itmay be subjected.

(10) The following system compo-nents:

(i) On a conventional drilling rig, akelly cock installed below the swivel(upper kelly cock), essentially full-opening, and a similar valve of such de-sign that it can be run through theBOP stack (strippable) installed at thebottom of the kelly (lower kelly cock).With a mud motor in service and whileusing drill pipe in lieu of a kelly, onekelly cock located above and onestrippable kelly cock located below thejoint of drill pipe employed in lieu of akelly. On a top-drive system equippedwith a remote controlled valve, a sec-ond and lower strippable valve of a con-ventional kelly cock or comparabletype either manually or remotely con-trolled. All required manual and re-motely controlled valves of a kellycock or comparable type in a top-drivesystem shall be essentially full-openingand tested according to the test pres-sure and test frequency as stated in§ 250.57(d) of this part. A wrench to fiteach manually operable valve in a con-ventional drilling rig, mud motor, andtop-drive system shall be stored in a lo-cation readily accessible to the drillingcrew.

(ii) An inside BOP and an essentiallyfull-opening drill-string safety valve inthe open position on the rig floor at alltimes while drilling operations arebeing conducted. These valves shall bemaintained on the rig floor to fit allconnections that are in the drill string.A wrench to fit the drill-string safetyvalve shall be stored in a location read-ily accessible to the drilling crew.

(iii) A safety valve available on therig floor assembled with the properconnection to fit the casing stringbeing run in the hole.

(11) Locking devices installed on theram-type preventers.

(e) Subsea BOP requirements. (1) Priorto drilling below surface and inter-mediate casing, a BOP system shall beinstalled consisting of at least four re-mote controlled, hydraulically oper-ated BOP’s including at least twoequipped with pipe rams, one withblind-shear rams, and one annulartype. A subsea accumulator closingunit or a suitable alternate approvedby the District Supervisor is required


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to provide fast closure of the BOP com-ponents and to operate all criticalfunctions in case of a loss of the powerfluid connection to the surface. Whenproposed casing setting depths or localgeology indicate the need for a BOP toprovide safety during the drilling ofthe surface hole, the District Super-visor may require that a subsea BOPsystem be installed prior to drillingbelow the conductor casing.

(2) The BOP system shall include op-erable dual-pod control systems nec-essary to ensure proper and independ-ent operation of the BOP system func-tions when drilling below the surfacecasing.

(3) Prior to the removal of the ma-rine riser, the riser shall be displacedwith seawater. Sufficient hydrostaticpressure or other suitable precautions,such as mechanical or cement plugs orclosing the BOP, shall be maintainedwithin the wellbore to compensate forthe reduction in pressure and to main-tain a safe controlled well condition.

(4) Any necessary repair or replace-ment of the BOP system or a systemcomponent after installation shall beaccomplished under safe controlledconditions, (e.g., after casing has beencemented but prior to drilling out thecasing shoe or by setting a cementplug, bridge plug, or a packer).

(5) When a subsea BOP system is tobe used in an area which is subject toice scour, the BOP stack shall beplaced in an excavation (glory hole) ofsufficient depth to assure that the topof the stack is below the deepest prob-able ice-scour depth.

(f) Surface BOP requirements. Prior todrilling below surface or intermediatecasing, a BOP system shall be installedconsisting of at least four remote con-trolled, hydraulically operated BOP’sincluding at least two equipped withpipe rams, one with blind rams, andone annular type.

(g) Tapered drill-string operations. (1)Prior to commencing tapered drill-pipeoperations, the BOP stack shall beequipped with conventional and/orvariable-bore pipe rams installed intwo or more ram cavities to providethe following:

(i) Two sets of pipe rams capable ofsealing around the larger size drillstring, and

(ii) One set of pipe rams capable ofsealing around the smaller size drillstring.

(2) Subsea BOP systems shall haveblind-shear ram capability. SurfaceBOP systems shall have blind ram ca-pability.

§ 250.57 Blowout preventer systemstests, actuations, inspections, andmaintenance.

(a) Prior to conducting high-pressuretests, all BOP systems shall be testedto a low pressure of 200 to 300 psi.

(b) Surface ram-type BOP’s and thechoke manifold shall be pressure testedwith water to rated working pressureor as otherwise approved by the Dis-trict Supervisor. The annular-typeBOP shall be pressure tested withwater to 70 percent of its rated workingpressure or as otherwise approved bythe District Supervisor.

(c) Subsea BOP system componentsshall be stump pressure tested at thesurface with water to their rated work-ing pressure, except that the annular-type BOP shall not be pressure testedabove 70 percent of its rated workingpressure. After the installation of theBOP stack on the seafloor, the ram-type BOP’s and choke manifold shall bepressure tested to rated working pres-sure or as otherwise approved by theDistrict Supervisor. The annular pre-venter shall be pressure tested to 70percent of its rated working pressureor as otherwise approved by the Dis-trict Supervisor.

(d) In conjunction with the weeklypressure test of surface and subsea BOPsystems required in paragraph (e) ofthis section, the choke manifoldvalves; upper and lower kelly cocks;top-drive, inside-BOP, and the drill-string safety valves shall be pressuretested to pipe-ram test pressures orotherwise approved by the District Su-pervisor. Safety valves assembled withproper casing connections shall be ac-tuated prior to running casing.

(e) Surface and subsea BOP systemsshall be pressure tested as follows:

(1) When installed.(2) Before drilling out each string of

casing or before continuing operationsin cases where the cement is not drilledout.


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(3) At least once each week, but notexceeding 7 days between pressuretests, alternating between control sta-tions and pods. If either control stationor pod is not functional, further drill-ing operations shall be suspended untilthat system becomes operable. A pe-riod of more than 7 days between BOPtests is allowed when there is stuckdrill pipe or pressure-control oper-ations and remedial efforts are beingperformed, provided that the pressuretests are conducted as soon as possibleand before normal operations resume.The reason for postponing pressuretesting shall be entered into thedriller’s report. Pressure testing shallbe performed at intervals to allow eachdrilling crew to operate the equipment.The weekly pressure test is not re-quired for blind and blind-shear rams.

(4) Blind and blind-shear rams shallbe actuated at least once every 7 days.Closing pressure on the blind and blind-shear rams greater than that necessaryto indicate proper operation of therams is not required.

(5) Variable bore-pipe rams shall bepressure-tested against all sizes of pipein use, excluding drill collars and bot-tom-hole tools.

(6) Following the disconnection or re-pair of any well-pressure containmentseal in the wellhead/BOP stack assem-bly but limited to the affected compo-nent.

(f) All BOP systems and marine risersshall be inspected and maintained toassure that the equipment will func-tion properly. The BOP systems andmarine risers shall be visually in-spected at least once each day if theweather and sea conditions permit theinspection. Inspection of BOP systemsand marine risers may be accomplishedby the use of television equipment. TheDistrict Supervisor may approve alter-nate methods of inspection of marinerisers on dynamic-positioned rigs. Cas-ing risers on fixed structures andjackup rigs are not subject to the dailyunderwater inspection requirement.

(g) The lessee shall record pressureconditions during BOP tests on pres-sure charts, unless otherwise approvedby the District Supervisor. The test in-terval for each BOP component testedshall be sufficient to demonstrate thatthe component is effectively holding

pressure. The charts shall be certifiedas correct by the operator’s representa-tive at the facility.

(h) The time, date, and results of allpressure tests, actuations, and inspec-tions of the BOP system, system com-ponents, and marine risers shall be re-corded in the driller’s report. The BOPtests shall be documented in accord-ance with the following:

(1) The documentation shall indicatethe sequential order of BOP and auxil-iary equipment testing and the pres-sure and duration of each test. As analternate, the documentation in thedriller’s report may reference a BOPtest plan that contains the required in-formation and is retained on file at thefacility.

(2) The control station used duringthe test shall be identified in thedriller’s report. For a subsea system,the pod used during the test shall beidentified in the driller’s report.

(3) Any problems or irregularities ob-served during BOP and auxiliary equip-ment testing and any actions taken toremedy such problems or irregularitiesshall be noted in the driller’s report.

(4) Documentation required to be en-tered in the driller’s report may in-stead be referenced in the driller’s re-port. All records including pressurecharts, driller’s report, and referenceddocuments pertaining to BOP tests, ac-tuations, and inspections, shall beavailable for MMS review at the facil-ity for the duration of the drilling ac-tivity. Following completion of thedrilling activity, all such records shallbe retained for a period of 2 years atthe facility, at the lessee’s field officenearest the OCS facility, or at anotherlocation conveniently available to theDistrict Supervisor.

[53 FR 10690, Apr. 1, 1988, as amended at 56FR 1914, Jan. 18, 1991]

§ 250.58 Well-control drills.

(a) Well-control drills shall be con-ducted for each drilling crew in accord-ance with the following requirements:

(1) Drills shall be designed to ac-quaint each crew member with eachmember’s function at the particulartest station so each member can per-form their functions promptly and effi-ciently.


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(2) A well-control drill plan, applica-ble to the particular site, shall be pre-pared for each crew member outliningthe assignments each member is to ful-fill during the drill and establishing aprescribed time for the completion ofeach portion of the drill. A copy of thecomplete well-control drill plan shallbe posted on the rig floor and/or bul-letin board.

(3) The drill shall be carried out dur-ing periods of activity selected to mini-mize the risk of sticking the drill pipeor otherwise endangering the oper-ation. In each of these drills, the reac-tion time of participants shall be meas-ured up to the point when the des-ignated person is prepared to activatethe closing sequence of the BOP sys-tem. The total time for the crew tocomplete its entire drill assignmentshall also be measured. This operationshall be recorded on the driller’s reportas ‘‘Well-Control Drill.’’ All drills shallbe initiated by the toolpusher throughthe raising of the float on the pit-leveldevice, activating the mud-return indi-cator, or its equivalent. This operationshall be performed at least once eachweek (well conditions permitting) witheach crew. The drills shall be timed sothey will cover a range of different op-erations which include on-bottom drill-ing and tripping. A diverter drill shallbe developed and conducted in a simi-lar manner for shallow operations.

(4) On-bottom drilling. A drill con-ducted while on bottom shall includethe following as practicable:

(i) Detect kick and sound alarm;(ii) Position kelly and tool joints so

connections are accessible from floor,but tool joints are clear of sealing ele-ments in BOP systems, stop pumps,check for flow, close in the well;

(iii) Record time;(iv) Record drill-pipe pressure and

casing pressure;(v) Measure pit gain and mark new

level;(vi) Estimate volume of additional

mud in pits;(vii) Weight sample of mud from suc-

tion pit;(viii) Check all valves on choke

manifold and BOP system for correctposition (open or closed);

(ix) Check BOP system componentsand choke manifold for leaks;

(x) Check flow line and choke ex-haust lines for flow;

(xi) Check accumulator pressure;(xii) Prepare to extinguish sources of

ignition;(xiii) Alert standby boat or prepare

safety capsule for launching;(xiv) Place crane operator on duty for

possible personnel evacuation;(xv) Prepare to lower escape ladders

and prepare other abandonment devicesfor possible use;

(xvi) Determine materials needed tocirculate out kick; and

(xvii) Time drill and enter drill re-port on driller’s report.

(5) Tripping pipe. A drill conductedduring a trip shall include the follow-ing as practicable:

(i) Detect kick and sound alarm;(ii) Install safety valve, close safety

valve;(iii) Position pipe, prepare to close

annular preventer;(iv) Install inside preventer, open

safety valve;(v) Record time;(vi) Record casing pressure;(vii) Check all valves on choke mani-

fold and BOP system for correct posi-tion (open or closed);

(viii) Check for leaks on BOP systemcomponent and choke manifold;

(ix) Check flow line and choke ex-haust lines for flow;

(x) Check accumulator pressure;(xi) Prepare to extinguish sources of

ignition;(xii) Alert standby boat or prepare

safety capsule for launching;(xiii) Place crane operator on duty

for possible personnel evacuation;(xiv) Prepare to lower escape ladders

and prepare other abandonment devicesfor possible use;

(xv) Prepare to strip back to bottom;and

(xvi) Time drill and enter drill reporton driller’s report.

(b) A well-control drill may be re-quired by a Minerals ManagementService (MMS) authorized representa-tive after consulting with the lessee’ssenior representative present.

§ 250.59 Diverter systems.(a) When drilling a conductor or sur-

face hole, all drilling units shall be


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30 CFR Ch. II (7-1-97 Edition)§ 250.60

equipped with a diverter system con-sisting of a diverter sealing element,diverter lines, and control systems un-less otherwise approved by the DistrictSupervisor for floating drilling oper-ations. The diverter system shall be de-signed, installed, and maintained so asto divert gases, water, mud, and othermaterials away from the facilities andpersonnel.

(b) No later than May 31, 1990, di-verter systems shall be in compliancewith the requirements of this section.The requirements applicable todiverters which were in effect April 1,1988 shall remain in effect until May 31,1990.

(c) The diverter system shall beequipped with remote-controlled valvesin the flow and vent lines that can beoperated from at least one remote-con-trol station in addition to the one onthe drilling floor. Any valve used in adiverter system shall be full-opening.No manual or butterfly valve shall beinstalled in any part of the divertersystem. There shall be a minimumnumber of turns in the vent line(s)downstream of the spool outlet flangeand the radius of curvature of turnsshall be as large as practicable. Allright-angle and sharp turns shall betargeted. Flexible hose may be used fordiverter lines instead of rigid pipe ifthe flexible hose has integral end cou-plings. The entire diverter system shallbe firmly anchored and supported toprevent whipping and vibration. All di-verter control instruments and linesshall be protected from physical dam-age from thrown and falling objects.

(d) For drilling operations conductedwith a surface wellhead configuration,the following shall apply:

(1) If the diverter system utilizesonly one spool outlet, branch linesshall be installed to provide downwinddiversion capability; and

(2) No spool outlet or diverter line in-ternal diameter shall be less than 10inches, except that dual spool outletsare acceptable provided that each out-let has a minimum internal diameterof 8 inches and that both outlets arepiped to overboard lines and that eachline downstream of the changeover nip-ple at the spool has a minimum inter-nal diameter of 10 inches.

(e) For drilling operations conductedwhere a floating or semisubmersibletype of drilling vessel is used and drill-ing fluids are circulated to the drillingvessel, the following shall apply:

(1) If the diverter system utilizesonly one spool outlet, branch linesshall be installed to provide downwinddiversion capability;

(2) No spool outlet or diverter line in-ternal diameter shall be less than 12inches; and

(3) Dynamically positioned drill shipsmay be equipped with a single vent lineprovided appropriate vessel heading ismaintained to allow for downwind di-version.

(f) The diverter sealing element anddiverter valves shall be pressure testedto a minimum of 200 psi when nippledup on conductor casing with a surfacewellhead configuration. No more than 7days shall elapse between subsequentsimilar pressure tests. For surface andsubsea wellhead configurations, the di-verter sealing element, diverter valves,and diverter-control systems, includingthe remote control system, shall be ac-tuation-tested and the vent lines flowtested when first installed. Subsequentactuation tests shall be conducted notless than once every 24-hour periodthereafter alternating between controlstations. All pressure test, flow test,and actuation results shall be recordedin the driller’s report.

(g) Diverter systems and componentsfor use in subfreezing conditions shallbe suitable for use under these condi-tions.

§ 250.60 Mud program.

(a) General requirements. The quan-tities, characteristics, use, and testingof drilling mud and the related drillingprocedures shall be designed and imple-mented to prevent the loss of well con-trol.

(b) Mud control. (1) Before startingout of the hole with drill pipe, the mudshall be properly conditioned by cir-culation with the drill pipe just off bot-tom to the extent that a volume ofdrilling mud equal to the annular vol-ume is displaced. This procedure maybe omitted if proper documentation inthe driller’s report shows the following:


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(i) There is no indication of influx offormation fluids prior to starting topull the drill pipe from the hole.

(ii) The weight of the returning mudis essentially the same as the weight ofthe mud entering the hole. In the eventthat the returning mud is lighter thanthe entering mud by a weight differen-tial equal to or greater than 0.2 poundsper gallon (1.5 pounds per cubic foot),the mud shall be circulated until a vol-ume of drilling mud equal to the annu-lar volume is displaced, and the mudproperties measured to assure thatthere has been no influx of gas or liq-uid.

(iii) Other mud properties recordedon the daily drilling log are within thelimits established by the approved mudprogram.

(2) When mud in the hole is cir-culated, the driller’s report shall be sonoted.

(3) When coming out of the hole withdrill pipe, the annulus shall be filledwith mud before the change in mudlevel decreases the hydrostatic pres-sure by 75 psi, or every five stands ofdrill pipe, whichever gives a lower de-crease in hydrostatic pressure. Thenumber of stands of drill pipe and drillcollars that may be pulled prior to fill-ing the hole and the equivalent mudvolume shall be calculated and postednear the driller’s station. A mechani-cal, volumetric, or electronic device formeasuring the amount of mud requiredto fill the hole shall be utilized.

(4) Drill pipe and downhole tool run-ning and pulling speeds shall be at con-trolled rates so as not to induce an in-flux of formation fluids from the ef-fects of swabbing nor cause a loss ofdrilling fluid and corresponding hydro-static pressure decrease from the ef-fects of surging.

(5) When there is an indication ofswabbing or influx of formation fluids,the safety devices and measures nec-essary to control the well shall be em-ployed. The mud shall be circulatedand conditioned, on or near bottom,unless well or mud conditions preventrunning the drill pipe back to the bot-tom.

(6) For each casing string, the maxi-mum pressure to be contained underthe BOP shall be posted near thedriller’s station.

(7) In areas where permafrost and/orhydrate zones may be present or areknown to be present, drilling fluid tem-peratures shall be controlled or othermeasures taken to drill safely throughthose zones.

(8) An operable mud-gas separatorand operable degasser shall be installedin the mud system prior to commence-ment of drilling operations and shall bemaintained for use throughout thedrilling of the well.

(9) The mud in the hole shall be cir-culated or reverse-circulated prior topulling the drill-stem test tools fromthe hole. If circulating out test fluid isnot feasible, test fluids may be bull-headed out of the drill-stem test stringand tools with an appropriate kill fluidprior to pulling the test tools.

(c) Mud-testing and monitoring equip-ment. (1) Mud-testing equipment shallbe maintained on the drilling rig at alltimes, and mud tests shall be per-formed once each tour, or more fre-quently, as conditions warrant. Suchtests shall be conducted in accordancewith industry-accepted practices andshall include mud density, viscosity,and gel strength, hydrogen-ion con-centration (pH), filtration, and othertests as may be deemed necessary bythe District Supervisor in the interestsof monitoring and maintaining mudquality for safe operations, preventionof downhole equipment problems, andfor kick detection. The results of thesetests shall be recorded in the driller’sreport.

(2) The following mud-system mon-itoring equipment shall be installedwith derrick floor indicators and usedwhen mud returns are established andthroughout subsequent drilling oper-ations:

(i) Recording mud-pit level indicatorto determine mud-pit volume gains andlosses. This indicator shall includeboth a visual and an audible warningdevice.

(ii) Mud-volume measuring device toaccurately determine mud volumes re-quired to fill the hole on trips.

(iii) Mud-return indicator deviceswhich indicate the relationship be-tween mud-return flow rate and pumpdischarge rate. This indicator shall in-clude both a visual and an audiblewarning device.


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30 CFR Ch. II (7-1-97 Edition)§ 250.61

(iv) Gas-detecting equipment to mon-itor the drilling mud returns with indi-cators located in the mud-logging com-partment or on the rig floor. If the in-dicators are only in the mud-loggingcompartment, there shall be a means ofimmediate communication with the rigfloor, and the gas-detecting equipmentshall be continually manned. If the in-dicators are on the rig floor only, anaudible alarm shall be installed.

(d) Mud quantities. (1) Quantities ofmud and mud materials at the drill siteshall be utilized, maintained, and re-plenished as necessary to ensure wellcontrol. Those quantities shall bebased on known or anticipated drillingconditions to be encountered, rig stor-age capacity, weather conditions, andestimated time for delivery.

(2) Daily inventories of mud and mudmaterials including weight materialsand additives at the drill site shall berecorded and those records maintainedat the well site.

(3) Drilling operations shall be sus-pended in the absence of sufficientquantities of mud and mud materialsto maintain well control.

(e) Safety precautions in mud-handlingareas. Mud-handling areas which areclassified as per API RP 500B wheredangerous concentrations of combus-tible gas may accumulate shall beequipped with ventilation systems andgas monitors as described below nolater than May 31, 1989. Regulatory re-quirements in effect on April 1, 1988 areapplicable until May 31, 1989.

(1) Be ventilated with high-capacitymechanical ventilation systems capa-ble of replacing the air once every 5minutes or 1.0 cubic feet of air-volumeflow per minute per square foot of area,whichever is greater, unless such ven-tilation is provided by natural means.If not continuously activated, mechan-ical ventilation systems shall be acti-vated on signal from gas detectors thatare operational at all times indicatingthe presence of 1 percent or more of gasby volume.

(2) Be maintained at a negative pres-sure relative to an adjacent area if me-chanical ventilation is installed tomeet the requirements in paragraph(e)(1) of this section and dischargesmay be hazardous. The negative pres-sure areas shall be protected with at

least one of the following: (i) A pres-sure-sensitive alarm, (ii) open-dooralarms on each access to the area, (iii)automatic door-closing devices, (iv) airlocks, or (v) other devices as approvedby the District Supervisor.

(3) Be fitted with gas detectors andalarms except in open areas where ade-quate ventilation is provided by natu-ral means.

(4) Be equipped with either explosion-proof or pressurized electrical equip-ment to prevent the ignition of explo-sive gases. Where air is used for pres-suring, the air intake shall be locatedoutside of, and as far as practicablefrom, hazardous areas.

(5) Mechanical ventilation systemsshall be fitted with alarms which areactivated upon a failure of the system.

(6) Gas detection systems shall betested for operation and recalibrated ata frequency such that no more than 90days shall elapse between tests.

[53 FR 10690, Apr. 1, 1988, as amended at 55FR 47752, Nov. 15, 1990]

§ 250.61 Securing of wells.A downhole safety device such as a

cement plug, bridge plug, or packershall be timely installed when drillingoperations are interrupted by eventssuch as those which force evacuation ofthe drilling crew, prevent station keep-ing, or require repairs to major drillingor well-control equipment. In floatingdrilling operations, the use of blind-shear rams or pipe rams and an insideBOP may be approved by the DistrictSupervisor in lieu of the above require-ments if supported by evidence of spe-cial circumstances and/or the lack ofsufficient time.

§ 250.62 Field drilling rules.When geological and engineering in-

formation available in a field enables aDistrict Supervisor to determine spe-cific operating requirements appro-priate to wells to be drilled in the field,field drilling rules may be establishedon the initiative of the District Super-visor, or in response to a request froma lessee. Such rules may modify the re-quirements of this subpart. After fielddrilling rules have been established, de-velopment wells to which such rulesapply shall be drilled in accordancewith such rules and other requirements


269


of this subpart. Field drilling rulesmay be amended or cancelled for causeat any time upon the initiative of theDistrict Supervisor or upon the ap-proval of a request by a lessee.

§ 250.63 Supervision, surveillance, andtraining.

(a) The lessee shall provide onsite su-pervision of drilling operations on a 24-hour per day basis.

(b) From the time drilling operationsare initiated and until the well is com-pleted or abandoned, a member of thedrilling crew or the toolpusher shallmaintain rig-floor surveillance con-tinuously, unless the well is securedwith BOP’s, bridge plugs, packers, orcement plugs.

(c) Lessee and drilling contractorpersonnel shall be trained and qualifiedin accordance with the provisions ofSubpart O of this part and MMS Train-ing Standard MMS–OCS–T 1, Trainingand Qualifications of Personnel inWell-Control Equipment and Tech-niques for Drilling Offshore Locations(Second Edition). Records of specifictraining which lessee and drilling con-tractor personnel have successfullycompleted, the dates of completion,and the names and dates of the coursesshall be maintained at the drill site.

§ 250.64 Applications for permit todrill.

(a) Prior to commencing the drillingof a well under an approved Explo-ration Plan, Development and Produc-tion Plan, or Development OperationsCoordination Document, the lesseeshall file a Form MMS–123, APD, withthe District Supervisor for approval.Prior to commencing operations, writ-ten approval from the District Super-visor must be received by the lessee un-less oral approval has been given pur-suant to § 250.6(a).

(b) The APD’s for wells to be drilledfrom mobile drilling units shall includethe following:

(1) An identification of the maximumenvironmental and operational condi-tions the rig is designed to withstand.

(2) Applicable current documentationof operational limitations imposed bythe American Bureau of Shipping clas-sification or other appropriate classi-fication society and either a U.S. Coast

Guard Certificate of Inspection or aU.S. Coast Guard Letter of Compliance.

(3) For frontier areas, the design andoperating limitations beyond whichsuspension, curtailment, or modifica-tion of drilling or rig operations are re-quired (e.g., vessel motion, offset, riserangle, anchor tensions, wind speed,wave height, currents, icing or ice-loading, settling, tilt or lateral move-ment, resupply capability) and the con-tingency plans which identify actionsto be taken prior to exceeding the de-sign or operating limitations of the rig.

(4) A program which provides forsafety in drilling operations where afloating or semisubmersible type ofdrilling vessel is used and formationcompetency at the structural and/orconductor casing setting depth(s) is(are) not adequate to permit circula-tion of drilling fluids to the vesselwhile drilling the conductor and/or sur-face hole. This program shall includeall known pertinent information in-cluding seismic and geologic data,water depth, drilling-fluid hydrostaticpressure, a schematic diagram indicat-ing the equipment to be installed fromthe rotary table to the proposed con-ductor and/or surface casing seat(s),and the contingency plan for movingoff location.

(c) The APD’s shall include rated ca-pacities of the proposed drilling unitand of major drilling equipment.

(d) In those areas which are subjectto subfreezing conditions, the lesseeshall furnish evidence that the drillingequipment, BOP system and compo-nents, drilling safety systems, divertersystems, and other associated equip-ment and materials are suitable fordrilling operations under subfreezingconditions.

(e) After a drilling unit has been ap-proved for use in an MMS District, theinformation listed in paragraphs (b) (1),(2), and (3), (c), and (d) of this sectionneed not be resubmitted unless re-quired by the District Supervisor orthere are changes in equipment that af-fect the rated capacity of the unit.

(f) An APD shall include the follow-ing in addition to a fully completedForm MMS–123:

(1) A plat, drawn to a scale of 2,000feet to the inch, showing the surfaceand subsurface location of the well to


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30 CFR Ch. II (7-1-97 Edition)§ 250.64

be drilled and of all the wells pre-viously drilled in the vicinity fromwhich information is available. Loca-tions shall be indicated in feet from theblock line.

(2) The design criteria considered forthe well and for well control, includingthe following:

(i) Pore pressures.(ii) Formation fracture gradients.(iii) Potential lost circulation zones.(iv) Mud weights.(v) Casing setting depths.(vi) Anticipated surface pressures

(which for purposes of this section aredefined as the pressure which can rea-sonably be expected to be exerted upona casing string and its related wellheadequipment). In the calculation of ananticipated surface pressure, the lesseeshall take into account the drilling,completion, and producing conditions.The lessee shall consider mud densitiesto be used below various casing strings,fracture gradients of the exposed for-mations, casing setting depths, totalwell depth, formation fluid type, andother pertinent conditions. Consider-ations for calculating anticipated sur-face pressure may vary for each seg-ment of the well. The lessee shall in-clude as a part of the statement of an-ticipated surface pressures the calcula-tions used to determine these pressuresduring the drilling phase and the com-pletion phase, including the antici-pated surface pressure used for produc-tion string design.

(vii) If a shallow hazards site surveyis conducted, the lessee shall submitwith or prior to the submittal of theAPD, two copies of a summary reportdescribing the geological and manmadeconditions present. The lessee shallalso submit two copies of the site mapsand data records identified in the sur-vey strategy.

(viii) Permafrost zones, if applicable.(3) A BOP equipment program includ-

ing the following:(i) The pressure rating of BOP equip-

ment.(ii) A well-control procedure for use

of the annular preventer for those wellswhere the anticipated surface pressureexceeds the rated working pressure ofthe annular preventer.

(iii) A description of subsea BOP ac-cumulator system or other type ofclosing system proposed for use.

(iv) A schematic drawing of the di-verter system to be used (plan and ele-vation views) showing spool outlet in-ternal diameter(s); diverter-linelengths and diameters, burst strengths,and radius of curvature at each turn;valve type, size, working pressure rat-ing, and location; the control instru-mentation logic; and the operating pro-cedure to be used by lessee or contrac-tor personnel.

(v) A schematic drawing of the BOPstack showing the inside diameter ofthe BOP stack, and the number of an-nular, pipe ram, variable-bore piperam, blind ram, and blind-shear rampreventers.

(4) A casing program including thefollowing:

(i) Casing size, weight, grade, type ofconnection, and setting depth;

(ii) Casing design safety factors fortension, collapse, and burst with theassumptions made to arrive at thesevalues; and

(iii) In areas containing permafrost,casing programs that incorporate set-ting depths for conductor and surfacecasing based on the anticipated depthof the permafrost at the proposed welllocation and which utilize the currentstate-of-the-art methods to safely drilland set casing. The casing programshall provide protection from thaw sub-sidence and freezeback effect, properanchorage, and well control.

(5) The drilling prognosis includingthe following:

(i) Projected plans for coring at spec-ified depths;

(ii) Projected plans for logging;(iii) Estimated depths to the top of

significant marker formations; and(iv) Estimated depths at which en-

counters with significant porous andpermeable zones containing freshwater, oil, gas, or abnormally pres-sured water are expected.

(6) A cementing program includingtype and amount of cement in cubicfeet to be used for each casing string.

(7) A mud program including theminimum quantities of mud and mudmaterials, including weight materials,to be kept at the site.


271


(8) A directional survey program fordirectionally drilled wells.

(9) A plot of the estimated pore pres-sures and formation fracture gradientsand the proposed mud weights and cas-ing setting depths on the same sheet.

(10) A H2S Contingency Plan, if appli-cable, and not submitted previously.

(11) Such other information as maybe required by the District Supervisor.

(g) Public information copies of theAPD shall be submitted in accordancewith § 250.17 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 58FR 49928, Sept. 24, 1993]

§ 250.65 Sundry notices and reports onwells.

(a) Notices of the lessee’s intentionto change plans, make changes inmajor drilling equipment, deepen orplug back a well, or engage in similaractivities and subsequent reports per-taining to such operations shall be sub-mitted to the District Supervisor onForm MMS–124, Sundry Notices andReports on Wells. Prior to commencingoperations, written approval must bereceived from the District Supervisorunless oral approval is obtained.

(b) The Form MMS–124 submittedshall contain a detailed statement ofthe proposed work that will materiallychange from the approved work de-scribed in the APD. Information sub-mitted shall include the present statusof the well, including the productionstring or last string of casing, the welldepth, the present production zonesand productive capability, and allother information specified on FormMMS–124. Within 30 days after comple-tion of the work, a subsequent detailedreport of all the work done and the re-sults obtained shall be submitted.

(c) A Form MMS–124 with a plat, cer-tified by a registered land surveyor,shall be filed as soon as the well’s finalsurveyed surface location, water depth,and the rotary kelly bushing elevationhave been determined.

(d) Public information copies of Sun-dry Notices and Reports on Wells shallbe submitted in accordance with § 250.17of this part.


§ 250.66 Well records.

(a) Complete and accurate records foreach well and of all well operationsshall be retained for a period of 2 yearsat the lessee’s field office nearest theOCS facility or at another locationconveniently available to the DistrictSupervisor. The records shall contain adescription of any significant malfunc-tion or problem; all the formationspenetrated; the content and characterof oil, gas, and other mineral depositsand water in each formation; the kind,weight, size, grade, and setting depthof casing; all well logs and surveys runin the wellbore; and all other informa-tion required by the District Super-visor in the interests of resource eval-uation, waste prevention, conservationof natural resources, protection of cor-relative rights, safety, and environ-ment.

(b) When drilling operations are sus-pended, or temporarily prohibitedunder the provisions of § 250.10 of thispart, the lessee shall, within 30 daysafter termination of the suspension ortemporary prohibition or within 30days after the completion of any ac-tivities related to the suspension orprohibition, transmit to the DistrictSupervisor duplicate copies of therecords of all activities related to andconducted during the suspension ortemporary prohibition on, or attachedto, Form MMS–125, Well Summary Re-port, or Form MMS–124, as appropriate.

(c) Upon request by the Regional orDistrict Supervisor, the lessee shallfurnish the following:

(1) Copies of the records of any of thewell operations specified in paragraph(a) of this section;

(2) Paleontological reports identify-ing microscopic fossils by depth and/orwashed samples of drill cuttings nor-mally maintained by the lessee for pa-leontological determinations;

(3) Copies of the daily driller’s reportat a frequency as determined by theDistrict Supervisor. Items to be re-ported include spud dates, casing set-ting depths, cement quantities, casingcharacteristics, pressure integritytests, mud weights, kicks, lost returns,and any unusual activities; and


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(4) Legible, exact copies of servicecompany reports on cementing, per-forating, acidizing, analyses of cores,testing, or other similar services.

(d) As soon as available, the lesseeshall transmit copies (field or finalprints of individual runs) of logs orcharts of electrical, radioactive, sonic,and other well-logging operations, di-rectional-well surveys, and analyses ofcores. Composite logs of multiple runsand directional-well surveys shall betransmitted to the District Supervisorin duplicate as soon as available butnot later than 30 days after completionof each well.

(e) If the drilling unit moves from thewellbore prior to completing the well,the lessee shall submit to the DistrictSupervisor copies of the well recordswith completed Form MMS–124, within30 days after moving from the wellbore.

(f) If the Regional or District Super-visor determines that circumstanceswarrant, the lessee shall submit anyother reports and records of operations,including paleontological interpreta-tions based upon identification of mi-croscopic fossils, in the manner andform prescribed by the Regional or Dis-trict Supervisor.

(g) Records relating to the drilling ofa well shall be retained for a period of90 days after drilling operations arecompleted. Records relating to thecompletion of a well or of anyworkover activity which materially al-ters the completion configuration ormaterially affects or alters a hydro-carbon-bearing zone shall be kept untilthe well is permanently plugged andabandoned.


§ 250.67 Hydrogen sulfide.(a) What precautions must I take when

operating in an H2S area? You must:(1) Take all necessary and feasible

precautions and measures to protectpersonnel from the toxic effects of H2Sand to mitigate damage to propertyand the environment caused by H2S.You must follow the requirements ofthis section when conducting drilling,well-completion/well-workover, andproduction operations in zones withH2S present and when conducting oper-

ations in zones where the presence ofH2S is unknown. You do not need tofollow these requirements when operat-ing in zones where the absence of H2Shas been confirmed; and

(2) Follow your approved contingencyplan.

(b) Definitions. Terms used in thissection have the following meanings:

Facility means a vessel, a structure,or an artificial island used for drilling,well-completion, well-workover, and/orproduction operations.

H2S absent means:(1) Drilling, logging, coring, testing,

or producing operations have con-firmed the absence of H2S in concentra-tions that could potentially result inatmospheric concentrations of 20 ppmor more of H2S; or

(2) Drilling in the surrounding areasand correlation of geological and seis-mic data with equivalent stratigraphicunits have confirmed an absence of H2Sthroughout the area to be drilled.

H2S present means that drilling, log-ging, coring, testing, or producing op-erations have confirmed the presenceof H2S in concentrations and volumesthat could potentially result in atmos-pheric concentrations of 20 ppm ormore of H2S.

H2S unknown means the designationof a zone or geologic formation whereneither the presence nor absence of H2Shas been confirmed.

Well-control fluid means drilling mudand completion or workover fluid asappropriate to the particular operationbeing conducted.

(c) Classifying an area for the presenceof H2S. You must:

(1) Request and obtain an approvedclassification for the area from the Re-gional Supervisor before you begin op-erations. Classifications are ‘‘H2S ab-sent,’’ H2S present,’’ or ‘‘H2S un-known’’;

(2) Submit your request with yourapplication for permit to drill;

(3) Support your request with avail-able information such as geologic andgeophysical data and correlations, welllogs, formation tests, cores and analy-sis of formation fluids; and

(4) Submit a request for reclassifica-tion of a zone when additional data in-dicate a different classification is need-ed.


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(d) What do I do if conditions change?If you encounter H2S that could poten-tially result in atmospheric concentra-tions of 20 ppm or more in areas notpreviously classified as having H2Spresent, you must immediately notifyMMS and begin to follow requirementsfor areas with H2S present.

(e) What are the requirements for con-ducting simultaneous operations? Whenconducting any combination of drill-ing, well-completion, well-workover,and production operations simulta-neously, you must follow the require-ments in the section applicable to eachindividual operation.

(f) Requirements for submitting an H2SContingency Plan. Before you begin op-erations, you must submit an H2S Con-tingency Plan to the District Super-visor for approval. Do not begin oper-ations before the District Supervisorapproves your plan. You must keep acopy of the approved plan in the field,and you must follow the plan at alltimes. Your plan must include:

(1) Safety procedures and rules thatyou will follow concerning equipment,drills, and smoking;

(2) Training you provide for employ-ees, contractors, and visitors;

(3) Job position and title of the per-son responsible for the overall safety ofpersonnel;

(4) Other key positions, how these po-sitions fit into your organization, andwhat the functions, duties, and respon-sibilities of those job positions are;

(5) Actions that you will take whenthe concentration of H2S in the atmos-phere reaches 20 ppm, who will be re-sponsible for those actions, and a de-scription of the audible and visualalarms to be activated;

(6) Briefing areas where personnelwill assemble during an H2S alert. Youmust have at least two briefing areason each facility and use the briefingarea that is upwind of the H2S sourceat any given time;

(7) Criteria you will use to decidewhen to evacuate the facility and pro-cedures you will use to safely evacuateall personnel from the facility by ves-sel, capsule, or lifeboat. If you use heli-copters during H2S alerts, describe thetypes of H2S emergencies during whichyou consider the risk of helicopter ac-tivity to be acceptable and the pre-

cautions you will take during theflights;

(8) Procedures you will use to safelyposition all vessels attendant to the fa-cility. Indicate where you will locatethe vessels with respect to wind direc-tion. Include the distance from the fa-cility and what procedures you will useto safely relocate the vessels in anemergency;

(9) How you will provide protective-breathing equipment for all personnel,including contractors and visitors;

(10) The agencies and facilities youwill notify in case of a release of H2S(that constitutes an emergency), howyou will notify them, and their tele-phone numbers. Include all facilitiesthat might be exposed to atmosphericconcentrations of 20 ppm or more ofH2S;

(11) The medical personnel and facili-ties you will use if needed, their ad-dresses, and telephone numbers;

(12) H2S detector locations in produc-tion facilities producing gas containing20 ppm or more of H2S. Include an ‘‘H2SDetector Location Drawing’’ showing:

(i) All vessels, flare outlets,wellheads, and other equipment han-dling production containing H2S;

(ii) Approximate maximum con-centration of H2S in the gas stream;and

(iii) Location of all H2S sensors in-cluded in your contingency plan;

(13) Operational conditions when youexpect to flare gas containing H2S in-cluding the estimated maximum gasflow rate, H2S concentration, and dura-tion of flaring;

(14) Your assessment of the risks topersonnel during flaring and what pre-cautionary measures you will take;

(15) Primary and alternate methodsto ignite the flare and procedures forsustaining ignition and monitoring thestatus of the flare (i.e., ignited or ex-tinguished);

(16) Procedures to shut off the gas tothe flare in the event the flare is extin-guished;

(17) Portable or fixed sulphur dioxide(SO2)-detection system(s) you will useto determine SO2 concentration and ex-posure hazard when H2S is burned;

(18) Increased monitoring and warn-ing procedures you will take when the


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SO2 concentration in the atmospherereaches 2 ppm;

(19) Personnel protection measures orevacuation procedures you will initiatewhen the SO2 concentration in the at-mosphere reaches 5 ppm;

(20) Engineering controls to protectpersonnel from SO2; and

(21) Any special equipment, proce-dures, or precautions you will use ifyou conduct any combination of drill-ing, well-completion, well-workover,and production operations simulta-neously.

(g) Training program.(1) When and how often do employees

need to be trained? All operators andcontract personnel must complete anH2S training program to meet the re-quirements of this section:

(i) Before beginning work at the fa-cility; and

(ii) Each year, within 1 year aftercompletion of the previous class.

(2) What training documentation do Ineed? For each individual working onthe platform, either:

(i) You must have documentation ofthis training at the facility where theindividual is employed; or

(ii) The employee must carry a train-ing completion card.

(3) What training do I need to give tovisitors and employees previously trainedon another facility?

(i) Trained employees or contractorstransferred from another facility mustattend a supplemental briefing on yourH2S equipment and procedures beforebeginning duty at your facility;

(ii) Visitors who will remain on yourfacility more than 24 hours must re-ceive the training required for employ-ees by paragraph (g)(4) of this section;and

(iii) Visitors who will depart beforespending 24 hours on the facility areexempt from the training required foremployees, but they must, upon arriv-al, complete a briefing that includes:

(A) Information on the location anduse of an assigned respirator; practicein donning and adjusting the assignedrespirator; information on the safebriefing areas, alarm system, and haz-ards of H2S and SO2; and

(B) Instructions on their responsibil-ities in the event of an H2S release.

(4) What training must I provide to allother employees? You must train all in-dividuals on your facility on the:

(i) Hazards of H2S and of SO2 and theprovisions for personnel safety con-tained in the H2S Contingency Plan;

(ii) Proper use of safety equipmentwhich the employee may be required touse;

(iii) Location of protective breathingequipment, H2S detectors and alarms,ventilation equipment, briefing areas,warning systems, evacuation proce-dures, and the direction of prevailingwinds;

(iv) Restrictions and correctivemeasures concerning beards, spec-tacles, and contact lenses in conform-ance with ANSI Z88.2;

(v) Basic first-aid procedures applica-ble to victims of H2S exposure. Duringall drills and training sessions, youmust address procedures for rescue andfirst aid for H2S victims;

(vi) Location of:(A) The first-aid kit on the facility;(B) Resuscitators; and(C) Litter or other device on the fa-

cility.(vii) Meaning of all warning signals.(5) Do I need to post safety information?

You must prominently post safety in-formation on the facility and on ves-sels serving the facility (i.e,, basicfirst-aid, escape routes, instructionsfor use of life boats, etc.).

(h) Drills. (1) When and how often do Ineed to conduct drills on H2S safety dis-cussions on the facility? You must:

(i) Conduct a drill for each person atthe facility during normal duty hoursat least once every 7-day period. Thedrills must consist of a dry-run per-formance of personnel activities relat-ed to assigned jobs.

(ii) At a safety meeting or othermeetings of all personnel, discuss drillperformance, new H2S considerationsat the facility, and other updated H2Sinformation at least monthly.

(2) What documentation do I need? Youmust keep records of attendance for:

(i) Drilling, well-completion, andwell-workover operations at the facil-ity until operations are completed; and

(ii) Production operations at the fa-cility or at the nearest field office for1 year.


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(i) Visual and audible warning sys-tems—(1) How must I install wind direc-tion equipment? You must install wind-direction equipment in a location visi-ble at all times to individuals on or inthe immediate vicinity of the facility.

(2) When do I need to display oper-ational danger signs, display flags, or ac-tivate visual or audible alarms?

(i) You must display warning signs atall times on facilities with wells capa-ble of producing H2S and on facilitiesthat process gas containing H2S in con-centrations of 20 ppm or more.

(ii) In addition to the signs, you mustactivate audible alarms and displayflags or activate flashing red lightswhen atmospheric concentration of H2Sreaches 20 ppm.

(3) What are the requirements for signs?Each sign must be a high-visibility yel-low color with black lettering as fol-lows:

Letter height Wording

12 inches ............................... Danger.Poisonous Gas.Hydrogen Sulfide.

7 inches ................................. Do not approach if red flag isflying.

(Use appropriate wording atright).

Do not approach if red lightsare flashing.

(4) May I use existing signs? You mayuse existing signs containing the words‘‘Danger-Hydrogen Sulfide-H2S,’’ pro-vided the words ‘‘Poisonous Gas. DoNot Approach if Red Flag is Flying’’ or‘‘Red Lights are Flashing’’ in letteringof a minimum of 7 inches in height aredisplayed on a sign immediately adja-cent to the existing sign.

(5) What are the requirements for flash-ing lights or flags? You must activate asufficient number of lights or hoist asufficient number of flags to be visibleto vessels and aircraft. Each light mustbe of sufficient intensity to be seen byapproaching vessels or aircraft anytime it is activated (day or night).Each flag must be red, rectangular, aminimum width of 3 feet, and a mini-mum height of 2 feet.

(6) What is an audible warning system?An audible warning system is a publicaddress system or siren, horn, or othersimilar warning device with a uniquesound used only for H2S.

(7) Are there any other requirements forvisual or audible warning devices? Yes,you must:

(i) Illuminate all signs and flags atnight and under conditions of poor visi-bility; and

(ii) Use warning devices that are suit-able for the electrical classification ofthe area.

(8) What actions must I take when thealarms are activated? When the warningdevices are activated, the designatedresponsible persons must inform per-sonnel of the level of danger and issueinstructions on the initiation of appro-priate protective measures.

(j) H2S-detection and H2S monitoringequipment.—(1) What are the require-ments for an H2S detection system? AnH2S detection system must:

(i) Be capable of sensing a minimumof 10 ppm of H2S in the atmosphere;and

(ii) Activate audible and visualalarms when the concentration of H2Sin the atmosphere reaches 20 ppm.

(2) Where must I have sensors for drill-ing, well-completion, and well-workoveroperations? You must locate sensors atthe:

(i) Bell nipple;(ii) Mud-return line receiver tank

(possum belly);(iii) Pipe-trip tank;(iv) Shale shaker;(v) Well-control fluid pit area;(vi) Driller’s station;(vii) Living quarters; and(viii) All other areas where H2S may

accumulate.(3) Do I need mud sensors? The Dis-

trict Supervisor may require mud sen-sors in the possum belly in cases wherethe ambient air sensors in the mud-re-turn system do not consistently detectthe presence of H2S.

(4) How often must I observe the sen-sors? During drilling, well-completionand well-workover operations, youmust continuously observe the H2S lev-els indicated by the monitors in thework areas during the following oper-ations:

(i) When you pull a wet string of drillpipe or workover string;

(ii) When circulating bottoms-upafter a drilling break;

(iii) During cementing operations;(iv) During logging operations; and(v) When circulating to condition

mud or other well-control fluid.


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(5) Where must I have sensors for pro-duction operations? On a platform wheregas containing H2S of 20 ppm or greateris produced, processed, or otherwisehandled:

(i) You must have a sensor in rooms,buildings, deck areas, or low-layingdeck areas not otherwise covered byparagraph (j)(2) of this section, whereatmospheric concentrations of H2Scould reach 20 ppm or more. You musthave at least one sensor per 400 squarefeet of deck area or fractional part of400 square feet;

(ii) You must have a sensor in build-ings where personnel have their livingquarters;

(iii) You must have a sensor within 10feet of each vessel, compressor, well-head, manifold, or pump, which couldrelease enough H2S to result in atmos-pheric concentrations of 20 ppm at adistance of 10 feet from the component;

(iv) You may use one sensor to detectH2S around multiple pieces of equip-ment, provided the sensor is located nomore than 10 feet from each piece, ex-cept that you need to use at least twosensors to monitor compressors exceed-ing 50 horsepower;

(v) You do not need to have sensorsnear wells that are shut in at the mas-ter valve and sealed closed;

(vi) When you determine where toplace sensors, you must consider:

(A) The location of system fittings,flanges, valves, and other devices sub-ject to leaks to the atmosphere; and

(B) Design factors, such as the typeof decking and the location of firewalls; and

(vii) The District Supervisor may re-quire additional sensors or other mon-itoring capabilities, if warranted bysite specific conditions.

(6) How must I functionally test the H2SDetectors?

(i) Personnel trained to calibrate theparticular H2S detector equipmentbeing used must test detectors by ex-posing them to a known concentrationin the range of 10 to 30 ppm of H2S.

(ii) If the results of any functionaltest are not within 2 ppm or 10 percent,whichever is greater, of the appliedconcentration, recalibrate the instru-ment.

(7) How often must I test my detectors?

(i) When conducting drilling, drillstem testing, well-completion, or well-workover operations in areas classifiedas H2S present or H2S unknown, test alldetectors at least once every 24 hours.When drilling, begin functional testingbefore the bit is 1,500 feet (vertically)above the potential H2S zone.

(ii) When conducting production op-erations, test all detectors at leastevery 14 days between tests.

(iii) If equipment requires calibrationas a result of two consecutive func-tional tests, the District Supervisormay require that H2S-detection andH2S-monitoring equipment be function-ally tested and calibrated more fre-quently.

(8) What documentation must I keep?(i) You must maintain records of

testing and calibrations (in the drillingor production operations report, as ap-plicable) at the facility to show thepresent status and history of each de-vice, including dates and details con-cerning:

(A) Installation;(B) Removal;(C) Inspection;(D) Repairs;(E) Adjustments; and(F) Reinstallation.(ii) Records must be available for in-

spection by MMS personnel.(9) What are the requirements for near-

by vessels? If vessels are stationed over-night alongside facilities in areas ofH2S present or H2S unknown, you mustequip vessels with an H2S-detectionsystem that activates audible and vis-ual alarms when the concentration ofH2S in the atmosphere reaches 20 ppm.This requirement does not apply tovessels positioned upwind and at a safedistance from the facility in accord-ance with the positioning procedure de-scribed in the approved H2S Contin-gency Plan.

(10) What are the requirements for near-by facilities? The District Supervisormay require you to equip nearby facili-ties with portable or fixed H2S detec-tor(s) and to test and calibrate thosedetectors. To invoke this requirement,the District Supervisor will considerdispersion modeling results from a pos-sible release to determine if 20 ppm H2Sconcentration levels could be exceededat nearby facilities.


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(11) What must I do to protect againstSO2 if I burn gas containing H2S? Youmust:

(i) Monitor the SO2 concentration inthe air with portable or strategicallyplaced fixed devices capable of detect-ing a minimum of 2 ppm of SO2;

(ii) Take readings at least hourly andat any time personnel detect SO2 odoror nasal irritation;

(iii) Implement the personnel protec-tive measures specified in the H2S Con-tingency Plan if the SO2 concentrationin the work area reaches 2 ppm; and

(iv) Calibrate devices every 3 monthsif you use fixed or portable electronicsensing devices to detect SO2.

(12) May I use alternative measures?You may follow alternative measuresinstead of those in paragraph (j)(11) ofthis section if you propose and the Re-gional Supervisor approves the alter-native measures.

(13) What are the requirements for pro-tective-breathing equipment? In an areaclassified as H2S present or H2S un-known, you must:

(i) Provide all personnel, includingcontractors and visitors on a facility,with immediate access to self-con-tained pressure-demand-type res-pirators with hoseline capability andbreathing time of at least 15 minutes.

(ii) Design, select, use, and maintainrespirators to conform to ANSI Z88.2,American National Standard for Res-piratory Protection.

(iii) Make available at least twovoice-transmission devices, which canbe used while wearing a respirator, foruse by designated personnel.

(iv) Make spectacle kits available asneeded.

(v) Store protective-breathing equip-ment in a location that is quickly andeasily accessible to all personnel.

(vi) Label all breathing-air bottles ascontaining breathing-quality air forhuman use.

(vii) Ensure that vessels attendant tofacilities carry appropriate protective-breathing equipment for each crewmember. The District Supervisor mayrequire additional protective-breathingequipment on certain vessels attendantto the facility.

(viii) During H2S alerts, limit heli-copter flights to and from facilities tothe conditions specified in the H2S Con-

tingency Plan. During authorizedflights, the flight crew and passengersmust use pressure-demand-type res-pirators. You must train all membersof flight crews in the use of the par-ticular type(s) of respirator equipmentmade available.

(ix) As appropriate to the particularoperation(s), (production, drilling,well-completion or well-workover oper-ations, or any combination of them),provide a system of breathing-airmanifolds, hoses, and masks at the fa-cility and the briefing areas. You mustprovide a cascade air-bottle system forthe breathing-air manifolds to refill in-dividual protective-breathing appara-tus bottles. The cascade air-bottle sys-tem may be recharged by a high-pres-sure compressor suitable for providingbreathing-quality air, provided thecompressor suction is located in anuncontaminated atmosphere.

(k) Personnel safety equipment.—(1)What additional personnel-safety equip-ment do I need? You must ensure thatyour facility has:

(i) Portable H2S detectors capable ofdetecting a 10 ppm concentration ofH2S in the air available for use by allpersonnel;

(ii) Retrieval ropes with safety har-nesses to retrieve incapacitated per-sonnel from contaminated areas;

(iii) Chalkboards and/or note pads forcommunication purposes located onthe rig floor, shale-shaker area, the ce-ment-pump rooms, well-bay areas, pro-duction processing equipment area, gascompressor area, and pipeline-pumparea;

(iv) Bull horns and flashing lights;and

(v) At least three resuscitators onmanned facilities, and a number equalto the personnel on board, not to ex-ceed three, on normally unmanned fa-cilities, complete with face masks, ox-ygen bottles, and spare oxygen bottles.

(2) What are the requirements for ven-tilation equipment? You must:

(i) Use only explosion-proof ventila-tion devices;

(ii) Install ventilation devices inareas where H2S or SO2 may accumu-late; and


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(iii) Provide movable ventilation de-vices in work areas. The movable ven-tilation devices must be multidirec-tional and capable of dispersing H2S orSO2 vapors away from working person-nel.

(3) What other personnel safety equip-ment do I need? You must have the fol-lowing equipment readily available oneach facility:

(i) A first-aid kit of appropriate sizeand content for the number of person-nel on the facility; and

(ii) At least one litter or an equiva-lent device.

(l) Do I need to notify MMS in theevent of an H2S release? You must notifyMMS without delay in the event of agas release which results in a 15-minute time weighted average atmos-pheric concentration of H2S of 20 ppmor more anywhere on the facility.

(m) Do I need to use special drilling,completion and workover fluids or proce-dures? When working in an area classi-fied as H2S present or H2S unknown:

(1) You may use either water- or oil-base muds in accordance with§ 250.40(b)(1).

(2) If you use water-base well-controlfluids, and if ambient air sensors detectH2S, you must immediately conduct ei-ther the Garrett-Gas-Train test or acomparable test for soluble sulfides toconfirm the presence of H2S.

(3) If the concentration detected byair sensors in over 20 ppm, personnelconducting the tests must don protec-tive-breathing equipment conformingto paragraph (j)(13) of this section.

(4) You must maintain on the facilitysufficient quantities of additives forthe control of H2S, well-control fluidpH, and corrosion equipment.

(i) Scavengers. You must have scav-engers for control of H2S available onthe facility. When H2S is detected, youmust add scavengers as needed. Youmust suspend drilling until the scav-enger is circulated throughout the sys-tem.

(ii) Control pH. You must add addi-tives for the control of pH to water-base well-control fluids in sufficientquantities to maintain pH of at least10.0.

(iii) Corrosion inhibitors. You mustadd additives to the well-control fluid

system as needed for the control of cor-rosion.

(5) You must degas well-controlfluids containing H2S at the optimumlocation for the particular facility. Youmust collect the gases removed andburn them in a closed flare system con-forming to paragraph (q)(6) of this sec-tion.

(n) What must I do in the event of akick? In the event of a kick, you mustuse one of the following alternatives todispose of the well-influx fluids givingconsideration to personnel safety, pos-sible environmental damage, and pos-sible facility well-equipment damage:

(1) Contain the well-fluid influx byshutting in the well and pumping thefluids back into the formation.

(2) Control the kick by using appro-priate well-control techniques to pre-vent formation fracturing in an openhole within the pressure limits of thewell equipment (drill pipe, work string,casing, wellhead, BOP system, and re-lated equipment). The disposal of H2Sand other gases must be through pres-surized or atmospheric mud-separatorequipment depending on volume, pres-sure and concentration of H2S. Theequipment must be designed to recoverwell-control fluids and burn the gasesseparated from the well-control fluid.The well-control fluid must be treatedto neutralize H2S and restore andmaintain the proper quality.

(o) Well testing in a zone known to con-tain H2S. When testing a well in a zonewith H2S present, you must do all ofthe following:

(1) Before starting a well test, con-duct safety meetings for all personnelwho will be on the facility during thetest. At the meetings, emphasize theuse of protective-breathing equipment,first-aid procedures, and the Contin-gency Plan. Only competent personnelwho are trained and are knowledgeableof the hazardous effects of H2S must beengaged in these tests.

(2) Perform well testing with theminimum number of personnel in theimmediate vicinity of the rig floor andwith the appropriate test equipment tosafely and adequately perform the test.During the test, you must continuouslymonitor H2S levels.


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(3) Not burn produced gases exceptthrough a flare which meets the re-quirements of paragraph (q)(6) of thissection. Before flaring gas containingH2S, you must activate SO2 monitoringequipment in accordance with para-graph (j)(11) of this section. If you de-tect SO2 in excess of 2 ppm, you mustimplement the personnel protectivemeasures in your H2S ContingencyPlan, required by paragraph (f)(13)(iv)of this section. You must also followthe requirements of § 250.175. You mustpipe gases from stored test fluids intothe flare outlet and burn them.

(4) Use downhole test tools and well-head equipment suitable for H2S serv-ice.

(5) Use tubulars suitable for H2S serv-ice. You must not use drill pipe for welltesting without the prior approval ofthe District Supervisor. Water cush-ions must be thoroughly inhibited inorder to prevent H2S attack on metals.You must flush the test string fluidtreated for this purpose after comple-tion of the test.

(6) Use surface test units and relatedequipment that is designed for H2Sservice.

(p) Metallurgical properties of equip-ment. When operating in a zone withH2S present, you must use equipmentthat is constructed of materials withmetallurgical properties that resist orprevent sulfide stress cracking (alsoknown as hydrogen embrittlement,stress corrosion cracking, or H2S em-brittlement), chloride-stress cracking,hydrogen-induced cracking, and otherfailure modes. You must do all of thefollowing:

(1) Use tubulars and other equipment,casing, tubing, drill pipe, couplings,flanges, and related equipment that isdesigned for H2S service.

(2) Use BOP system components,wellhead, pressure-control equipment,and related equipment exposed to H2S-bearing fluids that conform to NACEStandard MR.01–75–96.

(3) Use temporary downhole well-se-curity devices such as retrievablepackers and bridge plugs that are de-signed for H2S service.

(4) When producing in zones bearingH2S, use equipment constructed of ma-terials capable of resisting or prevent-ing sulfide stress cracking.

(5) Keep the use of welding to a mini-mum during the installation or modi-fication of a production facility. Weld-ing must be done in a manner that en-sures resistance to sulfide stress crack-ing.

(q) General requirements when operat-ing in an H2S zone—(1) Coring oper-ations. When you conduct coring oper-ations in H2S-bearing zones, all person-nel in the working area must wear pro-tective-breathing equipment at least 10stands in advance of retrieving the corebarrel. Cores to be transported must besealed and marked for the presence ofH2S.

(2) Logging operations. You must treatand condition well-control fluid in usefor logging operations to minimize theeffects of H2S on the logging equip-ment.

(3) Stripping operations. Personnelmust monitor displaced well-controlfluid returns and wear protective-breathing equipment in the workingarea when the atmospheric concentra-tion of H2S reaches 20 ppm or if thewell is under pressure.

(4) Gas-cut well-control fluid or wellkick from H2S-bearing zone. If you decideto circulate out a kick, personnel inthe working area during bottoms-upand extended-kill operations must wearprotective-breathing equipment.

(5) Drill- and workover-string designand precautions. Drill- and workover-strings must be designed consistentwith the anticipated depth, conditionsof the hole, and reservoir environmentto be encountered. You must minimizeexposure of the drill- or workover-string to high stresses as much as prac-tical and consistent with well condi-tions. Proper handling techniques mustbe taken to minimize notching andstress concentrations. Precautionsmust be taken to minimize stressescaused by doglegs, improper stiffnessratios, improper torque, whip, abrasivewear on tool joints, and joint imbal-ance.

(6) Flare system. The flare outlet mustbe of a diameter that allows easy non-restricted flow of gas. You must locateflare line outlets on the downside ofthe facility and as far from the facilityas is feasible, taking into account theprevailing wind directions, the wake


280

30 CFR Ch. II (7-1-97 Edition)§ 250.70

effects caused by the facility and adja-cent structure(s), and the height of allsuch facilities and structures. Youmust equip the flare outlet with anautomatic ignition system including apilot-light gas source or an equivalentsystem. You must have alternatemethods for igniting the flare. Youmust pipe to the flare system used forH2S all vents from production processequipment, tanks, relief valves, burstplates, and similar devices.

(7) Corrosion mitigation. You must useeffective means of monitoring and con-trolling corrosion caused by acid gases(H2S and CO2) in both the downhole andsurface portions of a production sys-tem. You must take specific corrosionmonitoring and mitigating measures inareas of unusually severe corrosionwhere accumulation of water and/orhigher concentration of H2S exists.

(8) Wireline lubricators. Lubricatorswhich may be exposed to fluids con-taining H2S must be of H2S-resistantmaterials.

(9) Fuel and/or instrument gas. Youmust not use gas containing H2S for in-strument gas. You must not use gascontaining H2S for fuel gas without theprior approval of the District Super-visor.

(10) Sensing lines and devices. Metalsused for sensing line and safety-controldevices which are necessarily exposedto H2S-bearing fluids must be con-structed of H2S-corrosion resistant ma-terials or coated so as to resist H2Scorrosion.

(11) Elastomer seals. You must useH2S-resistant materials for all sealswhich may be exposed to fluids con-taining H2S.

(12) Water disposal. If you dispose ofproduced water by means other thansubsurface injection, you must submitto the District Supervisor an analysisof the anticipated H2S content of thewater at the final treatment vessel andat the discharge point. The District Su-pervisor may require that the water betreated for removal of H2S. The Dis-trict Supervisor may require the sub-mittal of an updated analysis if thewater disposal rate or the potentialH2S content increases.

(13) Deck drains. You must equip opendeck drains with traps or similar de-

vices to prevent the escape of H2S gasinto the atmosphere.

(14) Sealed voids. You must take pre-cautions to eliminate sealed spaces inpiping designs (e.g., slip-on flanges, re-inforcing pads) which can be invadedby atomic hydrogen when H2S ispresent.

[62 FR 3795, Jan. 27, 1997]

Subpart E—Oil and Gas Well-Completion Operations

§ 250.70 General requirements.

Well-completion operations shall beconducted in a manner to protectagainst harm or damage to life (includ-ing fish and other aquatic life), prop-erty, natural resources of the OCS in-cluding any mineral deposits (in areasleased and not leased), the national se-curity or defense, or the marine, coast-al, or human environment.

§ 250.71 Definition.

When used in this subpart, the fol-lowing term shall have the meaninggiven below:

Well-completion operations means thework conducted to establish the pro-duction of a well after the production-casing string has been set, cemented,and pressure-tested.

§ 250.72 Equipment movement.

The movement of well-completionrigs and related equipment on and off aplatform or from well to well on thesame platform, including rigging upand rigging down, shall be conducted ina safe manner. All wells in the samewell-bay which are capable of produc-ing hydrocarbons shall be shut in belowthe surface with a pump-through-typetubing plug and at the surface with aclosed master valve prior to movingwell-completion rigs and related equip-ment, unless otherwise approved by theDistrict Supervisor. A closed surface-controlled subsurface safety valve ofthe pump-through type may be used inlieu of the pump-through-type tubingplug, provided that the surface controlhas been locked out of operation. Thewell from which the rig or relatedequipment is to be moved shall also beequipped with a back-pressure valve


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Subpart D—Oil and Gas Drilling Operations · PDF file§250.50 Control of wells. ......

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